Properties Of Shale Research Articles

Experimental Study on the Mechanical Properties of Shale After Long-term of Immersion in Fracturing Fluids with Different pH

Experimental Study on the Mechanical Properties of Shale After Long-term of Immersion in Fracturing Fluids with Different pH

Effects of hydrostatic pressure on hydraulic fracturing properties of shale using X-ray computed tomography and acoustic emission

The study of the hydraulic fracturing characteristics in shale reservoirs is crucial for improving the permeability of shale gas reservoirs. In this study, hydraulic fracturing tests are conducted on full-diameter shale cores, and the hydraulic fracturing characteristics of shale with different bedding angles under high hydrostatic pressure are studied. The results show that under a hydrostatic pressure of 59 MPa, the shale sample will rupture twice in the breakdown stage during hydraulic fracturing. When the bedding inclination increases from 0° to 90°, the shale fracture breakdown pressure first decreases and then increases, showing an overall downward trend. Under high hydrostatic pressure, shale specimen surface fracture morphology and X-ray computed tomography reveal that a bedding angle close to 45° is more conducive to forming a complex hydraulic fracture network, which makes the fractal dimension of the fracture network larger. The bedding plane of shale is the direct cause of the diverse propagation patterns of hydraulic fractures. The b-value is a parameter that characterizes the magnitude–frequency relationship of an earthquake, and it is closely related to the rock rupture process. The b-value varies with different trends with the expansion of hydraulic fractures, but they all reach the lowest point before the failure of the shale sample. The higher the hydraulic fracture network complexity, the lower the peak b-value is. This work provides a qualitative understanding and scientific explanation of the hydraulic fracturing characteristics of anisotropic shale under hydrostatic pressure.

Variation in Pore Space and Structure of Organic‐rich Oil‐prone Shales from a Non‐marine Basin: Constraints from Organic Matter and Minerals

AbstractOrganic matter (OM) and minerals are major particle components of lacustrine shales. The influence of OM and minerals on pore space and structure in organic‐rich oil‐prone shales containing a large range of total organic carbon (TOC) contents is poorly understood. In this study, we investigated the variation in pore space and structure of low mature lacustrine shales in the Songliao Basin (NE China), based on a study of the mineralogy, petrography, geochemistry, and geophysical properties of shales. Different pore types make markedly different contributions to the mineral surface area (MSA) and pore volume (PV) of the shales. There exists a negative correlation between MSA/PV and TOC in mesopores (r2 = 0.75/0.65) and macropores (r2 = 0.74/0.68), and a positive correlation in micropores (r2 = 0.59/0.64), which are associated with the variation of mineral and TOC contents. A positive relationship between the throat/pore ratio and TOC (r2 = 0.82) shows an increase in throat radius and decrease in pore radius with increasing TOC content. This relationship is supported by the reduction in mean pore diameter (MPD) for large pores and increase in MPD for small pores. These variations are related to the decreased pores by quartz plus feldspar (Q + F) content, increased throats by clay minerals, and enhanced pore‐fill by OM. We propose that the variation of OM and minerals is a key control on the pore space and structure of low mature organic‐rich oil‐prone shales.

Dynamic Brazilian splitting experiment of bedding shale based on continuum-discrete coupled method

Exploring the dynamic mechanical properties of shale helps to understand the damage of shale reservoirs under dynamic loading. In this paper, static Brazilian splitting experiments were conducted to obtain the static Brazilian strength of shales with loading angles ranging from 0° – 90° (at 15° intervals), and corresponding bedding shale models were developed based on the discrete element method. Then, the split Hopkinson pressure bar system was simulated according to the coupling of the continuous-discrete method, and dynamic Brazilian splitting simulations with loading rates of 100 – 170 GPa/s were carried out. The experimental results show that the Brazilian strengths of the shale at a loading rate of 0.05 mm/s are 4.73 MPa – 7.63 MPa, and the shale matrix and bedding can be simulated using the Flatjoint and Linearpbond models, respectively. The model parameters calibrated by static Brazilian splitting experiments were not applicable under dynamic loading; the microscopic tensile strength of the matrix and bedding increased by 2.7 and 3.1, and the microscopic cohesion increased by 1.8 and 1.7, respectively, for dynamic simulation tests. At a loading rate of 115 GPa/s, the dynamic tensile strength of the shale was 14.5 MPa – 18.2 MPa and increased with the increase of loading angle. There is a linear correlation between the dynamic tensile strength and the loading rate. The loading rate affects the damage pattern of the shale, with cracks tending to expand along the bedding. As the loading rate increases, the primary energy dissipated changes gradually from fracturing the rock to an increase in kinetic energy of the broken fragments.

Experimental study on microstructure and mechanical properties of lacustrine shale under water-rock interaction

Experimental study on microstructure and mechanical properties of lacustrine shale under water-rock interaction

Nanoscale mechanical property variations concerning mineral composition and contact of marine shale

Mechanical properties of shales are key parameters influencing hydrocarbon production – impacting borehole stability, hydraulic fracture extension and microscale variations in in situ stress. We use Ordovician shale (Sichuan Basin, China) as a type-example to characterize variations in mineral particle properties at microscale including particle morphology, form of contact and spatial distribution via mineral liberation analysis (MLA) and scanning electron microscopy (SEM). Deformation-based constitutive models are then built using finite element methods to define the impact of various architectures of fracture and mineral distributions at nanometer scale on the deformation characteristics at macroscale. Relative compositions of siliceous, calcareous and clay mineral particles are shown to be the key factors influencing brittleness. Shales with similar mineral composition show a spectrum of equivalent medium mechanical properties due to differing particle morphology and mineral heterogeneity. The predominance of small particles and/or point-point contacts are conducive to brittle failure, in general, and especially so when quartz-rich. Fracture morphology, length and extent of filling all influence shale deformability. High aspect-ratio fractures concentrate stress at fracture tips and are conducive to extension, as when part-filled by carbonate minerals. As fracture spacing increases, stress transfer between adjacent fractures weakens, stress concentrations are amplified and fracture extension is favored. The higher the fractal dimension of the fracture and heterogeneity of the host the more pervasive the fractures. Moreover, when fractures extend, their potential for intersection and interconnection contributes to a reduction in strength and the promotion of brittle failure. Thus, these results provide important theoretical insights into the role of heterogeneity on the deformability and strength of shale reservoirs with practical implications for their stimulation and in the recovery of hydrocarbons from them.

Effects of gas components, reservoir property and pore structure of shale gas reservoir on the competitive adsorption behavior of CO2 and CH4

CO2 injection into shale gas reservoirs is deemed as a potential scheme to enhance CH4 recovery and achieve the ambition of carbon neutral. The insufficient research of binary gas competitive adsorption behavior at in-situ conditions of shale gas reservoirs, and the coupling control of gas components, shale properties, and pore structure on CO2 adsorption affinity limit its general application. Therefore, the competitive adsorption behavior of CO2 and CH4 at in-situ conditions is simulated using high-pressure multi-component adsorption experiments, and the effects of binary gas components, shale properties and pore structure on CO2 adsorption affinity are discussed. Subsequently, the mathematical and geological models of CO2 injection into Longmaxi shale gas reservoir enhancing CH4 recovery and achieving carbon sequestration are established based on experimental parameters and reservoir geological parameters, and the feasibility and expectation benefits are discussed. The results exhibit that selectivity coefficient of CO2 relative to CH4 (Sc) decreases with higher CO2 mole fraction, whereas it increases with higher total organic carbon content (TOC) and clay content. Both pore volume (PV) and specific surface area (SSA) have clear positive correlations with Sc. Overall, TOC is a crucial controlling factor of pore structure and adsorption capacity of shale, further, affects the adsorption affinity of CO2. The injection of CO2 into shale gas reservoir shows a promising application prospect in improving CH4 recovery and carbon emission reduction in geological and mathematical models, and the leakage risk is low after CO2 sequestration.

Capillary Pressure Behavior of CO2 - Shale System at Elevated Temperatures

In this study, changes in capillary entry pressure of shale when interacting with CO2, under different temperatures have been investigated. The combined impact of temperature and petrophysical properties of shale (water content, water activity, permeability and porosity) on capillary entry pressure was addressed. Pressure breakthrough measurements were used to evaluate the minimum entry pressure of CO2 through shale. A heavy-duty oven was used to vary the temperature in order to investigate the impact of temperature on CO2 capillary entry pressure through shale. Results showed that capillary entry pressure of shale when interacting with CO2 was highly affected by temperature. Higher temperatures decreased capillary entry pressure of shale. We believe that pore dilation, where pore throat size expands due to the application of heat, may have caused this decrease in capillary entry pressure. However, in some cases higher temperature activated clay swelling that may have caused an apparent decrease in pore throat radii of shale which translated into higher capillary entry pressure. Results also showed that there exists no distinct relationship between petrophysical properties of shale and its measured capillary entry pressure when interacting with CO2 at different temperatures. Heat could alter pore throat radii and cause pore dilation which may alter measured capillary entry pressure. Interfacial tension decreases with increasing temperature and that can be attributed to the weakening of intermolecular forces at the two immiscible fluids interface. Swelling of clay could be related to temperature-induced transition from passive to an active clay.

A New Adsorption Equation for Nano-Porous Shale Rocks and Its Application in Pore Size Distribution Analysis

Adsorption equations are important to analyze the pore size distribution (PSD) of shale and the adsorption behavior on it. However, the accurate description of nitrogen adsorption on shale by current adsorption equations is difficult to achieve due to the heterogeneous pore structure of shale. In our study, new adsorption isotherms that can properly depict the adsorbed amount of nitrogen were built for shale rocks considering both the processes of nitrogen adsorption and the cylindrical pore shape property of shale. When performing a regression analysis on five sets of experimental adsorption data using the developed adsorption equations, the R-square ranged from 0.739 to 0.987. Based on the pore shape determined by adsorption–desorption curves, the distinct R-square indicated that our equation is not valid for shale samples with ink-bottle pores and pores formed by schistose materials, but that it is suitable for shale samples with cylindrical pores and slit pores. Meanwhile, we precisely analyzed the PSDs of shale rocks based on the developed adsorption equations as capillary condensation volume is involved in the total adsorbed amount. Thus, the PSDs of shale rocks with cylindrical pore and slit pore were analyzed by the new adsorption equation.

On the consequences of shale desaturation: physicochemical and mechanical perspectives

Adsorption of water by desaturated shale could be misinterpreted as osmotic swelling. If the saturation state of shale is not known, one should not presume that osmosis is responsible for water adsorption and resultant swelling. Such presumption may overlook the fact that spontaneous imbibition could be responsible for most water adsorption and apparent swelling in desaturated shale. This work examines mechanisms responsible for water adsorption by desaturated shale and proposes a superimposing technique that separate water adsorption by imbibition from that by chemical and diffusion osmosis. Also, this work investigates the impact of desaturation on physicochemical and mechanical properties of shale using gravimetric measurements, ASTM methods., X-ray diffraction and pore fluid’s chemical composition analysis. Results show that water transport in desaturated shale is falsely attributed to osmotic swelling and that spontaneous imbibition is the main force driving water transport. In the absence of diffusion osmosis and hydraulic flow, amount of water adsorbed via spontaneous imbibition is 2–3 times higher than that adsorbed by chemical osmosis. For desaturated shale, results revealed that reduction in water activity is non- linearly proportional to desaturation (drying) time. Results also showed that compressive strength and Young’s modulus increased non-linearly as moisture content decreased.

Influence of Depositional and Diagenetic Processes on Caprock Properties of CO2 Storage Sites in the Northern North Sea, Offshore Norway

Characterization of caprock shale is critical in CO2 storage site evaluation because the caprock shale acts as a barrier for the injected buoyant CO2 plume. The properties of shales are complex and influenced by various processes; hence, it is challenging to evaluate the caprock quality. An integrated approach is therefore necessary for assessing seal integrity. In this study, we investigated the caprock properties of the Lower Jurassic Drake Formation shales from the proposed CO2 storage site Aurora (the Longship/Northern Lights CCS project), located in the Horda Platform area, offshore Norway. Wireline logs from 50 exploration wells, various 2D seismic lines, and two 3D seismic cubes were used to investigate the variations of the caprock properties. The Drake Formation was subdivided into upper and lower Drake units based on the lithological variations observed. Exhumation and thermal gradient influencing the caprock properties were also analyzed. Moreover, rock physics diagnostics were carried out, and caprock property maps were generated using the average log values to characterize the Drake Formation shales. In addiiton, pre-stack seismic-inverted properties and post-stack seismic attributes were assessed and compared to the wireline log-based analysis. The sediment source controlled at 61° N significantly influenced the depositional environment of the studied area, which later influenced the diagenetic processes and had various caprock properties. The upper and lower Drake units represent similar geomechanical properties in the Aurora area, irrespective of significant lithological variations. The Drake Formation caprock shale near the injection site shows less-ductile to less-brittle brittleness values. Based on the caprock thickness and shaliness in the Aurora injection site, Drake Formation shale might act as an effective top seal. However, the effect of injection-induced pressure changes on caprock integrity needs to be evaluated.

The rock mechanical properties of lacustrine shales: Argillaceous shales versus silty laminae shales

Rock mechanical properties are of crucial importance to shale reservoirs as they directly affect the production efficiency and hydraulic fracturing design. However, limited data exists for rock mechanical properties in lacustrine shales. We thus conducted a series of petrophysical and rock mechanical tests on lacustrine shales to study the difference between argillaceous shales and silty laminae shales. We observed distinctly different rock mechanical properties for these two types shales. Moreover, these two lithologies also showed significantly different Young's moduli and Ultimate strength. Mixed illite/smectite and organic matter content strongly affected the rock mechanical properties of the lacustrine shales and 3D x-ray imaging indicated that the argillaceous shales contained more open bedding fractures, transverse sub-fractures, and a complicated fracture network. In contrast, the silty laminae shales only contained a few open bedding fractures and sub-fractures propagating throughout the samples. It is concluded that the texture and micro-structure in the study shale reservoir determines their fracture complexity. We also conclude that lacustrine shales with high clay content can be extensively fractured and potentially achieve economical production, especially in case of argillaceous shales. The results of this study can therefore help optimize hydraulic fracturing and improve enhanced gas recovery in lacustrine shale reservoirs.

Rock Acoustics of Diagenesis and Cementation

We simulate the effects of diagenesis, cementation and compaction on the elastic properties of shales and sandstones with four different petro-elastic theories and a basin-evolution model, based on constant heating and sedimentation rates. We consider shales composed of clay minerals, mainly smectite and illite, depending on the burial depth, and the pore space is assumed to be saturated with water at hydrostatic conditions. Diagenesis in shale (smectite/illite transformation here) as a function of depth is described by a fifth-order kinetic equation, based on an Arrhenius reaction rate. On the other hand, quartz cementation in sandstones is based on a model that estimates the volume of precipitated quartz cement and the resulting porosity loss from the temperature history, using an equation relating the precipitation rate to temperature. Effective pressure effects (additional compaction) are accounted for using the Athy equation and the Hertz–Mindlin model. The petro-elastic models yield similar seismic velocities, despite the different levels of complexity and physics approaches, with increasing density and seismic velocities as a function of depth. The methodology provides a simple procedure to obtain the velocity of shales and sandstones versus temperature and pressure due to the diagenesis-cementation-compaction process.

Investigation on Hydration and Deformation Characteristics of Shale Using X-ray Computed Tomography

The physical and mechanical properties of shale are significant for completion engineering and fracturing design for shale oil and gas production. To further study the water effect and the deformation characteristics of shale, some cylindrical specimens were soaked at three periods (0, 20, and 60 days), the in situ uniaxial compression tests were conducted, and the CT technique was used at different hydration and loading stages. Based on the CT results, the image gray variance value in each hydration specimen was extracted; the evolution results show that the water imbibition has a significant influence on the structure of shale in the early soaking stage, and the influence degree is more evident in the external region. Moreover, the water influence on the mechanical property of shale was analyzed by comparing the failure characteristics of specimens with and without hydration; the CT results show that the hydration treatment affects the failure mode of shale. In addition, a new method based on the CT image was proposed to calculate the lateral strain; the evolution of the axial stress-strain curve reveals that the expansion phenomena exist before failure, and the evolution process includes four stages. At last, the differences in the deformation degree were discussed by analyzing the volumetric strain at different CT scanning layers; the results reflect the expansion or compression degree along with the specimen height. Those conclusions can help us further understand the water effect and the deformation characteristics of shale oil and gas reservoirs.

Prediction of driven pile resistances in shales considering weathering and time effects

The difficulty with shale sampling and testing and the lack of pile load tests in shales have created challenges with shale classification, pile resistance prediction, and understanding time-dependent pile responses. Treating shale as soil can yield a conservative pile design. Shales were classified into soil-based and rock-based depending on their weathering conditions, mechanical properties, and measured pile resistances. Failure behaviors of soil- and rock-based shales are discussed. Prediction equations were developed to account for predicting shale properties. Properties of rock-based shales decrease with the increase in weathering. New static analysis (SA) methods were proposed to predict unit shaft resistance ( qs) and unit end bearing ( qb) of piles in shales and validated. Our study yields higher resistance and efficiency factors for the proposed SA methods and piles in shales than existing SA methods developed for piles in soils. The qs in the soil-based shale exhibits pile setup, while the qs in rock-based shales experience both setup and relaxation. The qb in both soil-based and highly weathered shales is likely to experience pile setup. However, the qb in the moderately and slightly weathered shales experience both setup and relaxation.

Impacts of temperature on the mechanical properties of Longmaxi shale outcrops using instrumented nanoindentation

Shale plays an important role in the energy industry and enhanced characterization of the fundamental properties of shale is essential to the economic and safe exploration of this resource. This study investigates the elastic modulus, hardness, and creep behavior of Longmaxi shale outcrops at different temperatures using instrumented nanoindentation. The results show that as the temperature increases from 20 °C to 300 °C, an approximately 10% reduction in measured elastic modulus is observed in the tested samples, whereas the increase in hardness is relatively insignificant, partly because of a relatively high volume fraction of quartz content, i.e., 66.3%. As temperature increases, the tested shale samples undergo brittle to ductile deformation transition as suggested by the number of the pop-in events during indentation loading. The 20-second creep deformation increases by approximately 30% from room temperature to 300 °C and the observed maximum creep deformation is linearly correlated with hardness at all tested temperatures. A smooth surface can render a lower standard deviation in measured elastic modulus and hardness. While a rough surface can lead to an underestimation of hardness, due to the overestimation of the penetration depth as a consequence of surface asperities breakage during indentation.

Using Nanoindentation to Characterize the Mechanical and Creep Properties of Shale: Load and Loading Strain Rate Effects.

The mechanical and creep properties of shale strongly influence artificial hydraulic fracturing, wellbore stability, and the evaluation of reservoir performance in shale gas exploration. This study characterized these mechanical and creep properties at the microscale through nanoindentation tests and evaluated their dependence on the indentation test parameters, specifically, the indentation load and the loading strain rate. The mechanical parameters (the Young’s modulus and hardness) of shale were strongly influenced by the magnitude of an indentation load (2–400 mN). Both parameters decreased sharply as the load increased from 2 to 200 mN; they then remained relatively stable at loads of 200–400 mN, suggesting that large indentation loads (200–400 mN) can be used to detect the mechanical responses of bulk shale. In contrast, both parameters increased slightly as the loading strain rate increased from 0.005 to 0.1 s–1. The indentation creep (CIT), related to creep behavior, and the creep strain rate sensitivity (m), related to the creep mechanism of shale, both increased with increasing the indentation load, whereas they decreased with increasing the loading strain rate. This demonstrates that increasing the load or decreasing the loading strain rate can increase creep deformation in shale during nanoindentation creep testing. The values of m varied from 0.040 to 0.124 under different loading conditions, suggesting that dislocation power-law creep may be the main mechanism controlling creep in shale. This study standardizes the testing parameters for the characterization of the mechanical properties of shale by nanoindentation testing and also advances our understanding of the deformation mechanisms of shale at the microscale.

Characteristics of Lithofacies Combinations and Reservoir Property of Carbonate-Rich Shale in Dongying Depression, Eastern China

Drilling has demonstrated that oil can be produced from the lacustrine shale in the upper part of the fourth member of the Shahejie Formation (Es4s) in Dongying Depression. These wells are often drilled in multiple lithofacies combinations, rather than a single lithofacies. Thus, it is necessary to classify the shale lithofacies combinations to optimize favorable exploration targets. The basic characteristics of carbonate mineral-rich shales in the Es4s were determined by core description, optical microscopy of thin sections, mineral analysis by X-ray diffraction, and scanning electron microscope analysis of argon ion-polished samples, combined with organic geochemical analysis and reservoir property analysis. The depositional setting was determined, and the lithofacies combinations of the shale were divided based on the depositional setting and vertical changes in lithofacies combination. Lithofacies combinations include 1) laminated argillaceous limestone interbedded with the calcareous mudstone (LLM); 2) laminated argillaceous limestone interbedded with dolomite (LLD); and 3) calcareous mudstone intercalated with argillaceous limestone (BML). LLM formed in a semi-humid climate, with limited detrital provenance, while LLD was mainly the product of an arid climate, little detrital input, semi-deep water, and a strongly reducing saltwater environment. In addition to the basal strata in the center of the depression, the LLD lithofacies combination was also widely developed on the gentle slope and the slope area transitional to deep depression in the south of the basin. BML was mainly formed in a semi-humid climate, brackish, deep water, and a reducing environment with many detrital provenances. The porosity in LLM and LLD consists of various types. Intercrystalline pores in clay minerals, intercrystalline pores and dissolution pores in carbonate minerals, interbedded fractures, and ultra-pressure fractures are well developed. The pore width distribution range of both LLM and LLD is large. The porosity of LLM is slightly higher than that of LLD. Interlayers with higher dolomite content have higher permeability. The types of pores in BML with no significant laminae characteristics are less abundant, and it is difficult to form an effective reservoir porosity network from the pores and microfractures, and hence, the reservoir physical properties are relatively poor. Oil saturation index indicates that both LLD and LLM of medium–low degree of evolution have good oil content.

Experimental Investigation of Shale Rock Properties Altering In-Situ Gas Density and Storage

Shale gas reservoir has become a crucial resource for the past decade to sustain growing energy needs while reducing the carbon intensity of energy systems relative to other fossil fuels. However, these reservoirs are geologically complex in their chemical composition and dominance of nano-scale pores, resulting in limited predictability of their effective storage capacity. To predict gas storage and estimate volumetric gas-in-place, in-situ gas properties need to be defined. However, only a few direct experimental measurements on in-situ gas properties are available in the literature, and the interactions between gas and the surrounding surface area of the medium remain poorly understood. In this study, gas invasion experiments were conducted in conjunction with 3D X-ray micro-CT imaging on three different shales, i.e., Bakken, Haynesville and Marcellus. Results show evidence of increased storage capacity in all cases, with different degrees of gas densification across the three shale specimens. The average of measured in-situ xenon density within the Bakken, Haynesville and Marcellus shale samples were found to be 171.53 kg/m3, 326.05 kg/m3 and 947 kg/m3, respectively. These measured densities are higher than their corresponding theoretical free gas density, though lower than the xenon density at boiling point, indicating that current practices of estimating adsorbed gas and gas in place, using boiling point liquid density, may be overestimated. The xenon densification factor in the Marcellus sample was found to be 7.4, indicating the most significant degree of localized densification. This densification factor drops to 2.6, and to 1.4, in the Haynesville and the Bakken sample, respectively. Characterization of shale composition and pore structure are presented, in order to assess the shale properties controlling in-situ gas density and storage capacity. Results indicate that the observed degree of gas densification in shales can be attributed to surface area and pore size. The findings in this work provide valuable reference for simulation to much more accurately predict gas storage in shales. More importantly, the contribution of this work lay a foundation to evaluate excess storage capacity of various gases in ranging tight formations.

Geochemical and physical alteration of clay-rich shales under supercritical CO2 conditions

The injection of Carbon Dioxide (CO2) into shale gas formations is a promising approach that not only reduces the impact of greenhouse gas on climate change but also enhances the gas recovery due to geochemical interactions between CO2 and clay minerals. However, these geochemical interactions have not been fully explored and changes in the petrophysical properties of shales have been reported over time. This paper evaluates the geochemical reactions and physical changes caused by the injection of supercritical carbon dioxide (ScCO2) on the properties of clay-rich shales. Samples from the Eagle Ford formation were collected and exposed to ScCO2 at different pressures ranging from 10 to 24 MPa at 70 °C. Analytical methods such as X-ray diffraction (XRD), Fourier transform infrared spectroscopy (FTIR) and thin-section microscopy were used to characterize the ScCO2-treated samples. The results showed dissolution of clays and precipitation of quartz with increasing ScCO2 treatment pressure. The content of carbonate minerals was also reduced at high pressure, which can be attributed to the reactions of the dolomite with H+ to form magnesium carbonate. The percentage of absorption of aromatic hydrocarbons and oxygenated groups gradually increased with increasing pressure, which can be attributed to the increase in CO2 adsorption. On the other hand, the absorption of aliphatic and hydroxyl groups decreased after treatment. ScCO2 treatment pressure is an important factor to evaluate the CO2 adsorption capacity of clay-rich shales. The presented results enrich the understanding of the interactions between CO2 and shale under different pressures, which may be helpful to determine the feasibility of long-term injection and storage in shale.